Downhole well pump

ABSTRACT

The pump and pump system of the present invention is designed to remove liquids, gas, sand and coal fines from gas and/or oil well bores. There is a need in the oil and gas industry to develop a more efficient operating pump that is capable of operating in wells that do not have enough bottom hole pressure to lift liquids to the surface causing the well to log off with fluids and if not economic, potentially be plugged prematurely. Additionally, this design will allow the producer the ability to conduct well bore maintenance such as acid flushes for perforation cleaning and scale batch treating for continued scale treatment.

RELATED APPLICATIONS

This application claims the benefit of prior filed copending U.S.Provisional Application No. 60/327,803 filed Oct. 9, 2001, and is a 371of PCT/US02/32462 filed Oct. 9, 2002.

FIELD OF INVENTION

The present invention relates generally to a pump system for removingnatural hydrocarbons or other fluids from a cased hole, i.e. a wellbore. More particularly, the present invention relates to a noveldownhole, gas-driven pump particularly suitable for removing fluids fromgas-producing wells.

BACKGROUND OF THE INVENTION

Increasing production demands and the need to extend the economic lifeof oil and gas wells have long posed a variety of problems. For example,as natural gas is produced, from a reservoir, the pressure within thereservoir decreases over time and some fluids that are entrained in thegas stream with higher pressures, break out due to lower reservoirpressures, and build up within the well bore. In time, the bottom holepressure will decrease to such an extent that the pressure will beinsufficient to lift the accumulated fluids to the surface. In turn, thehydrostatic pressure of the accumulated fluids causes the natural gasproduced from the “pay zone” to become substantially reduced or maybeeven completely static, reducing or preventing the gases/fluids fromflowing into the perforated cased hole and causing the well bore to logoff and possibly plugged prematurely for economic reasons.

The oil and gas industry has used various methods to lift fluids fromwell bores. The most common method is the use of a pump jack(reciprocating pump), but pump jack systems have given rise toadditional problems. Pump jack systems require a large mass of steel tobe installed on the surface and comprise several moving parts, includingcounter balance weights, which pose a significant risk of serious injuryto operators. Additionally, this type of artificial lift system causeswear to well tubing due to pumping rods that are constantly moving upand down inside the tubing. Consequently, pump jack systems havesignificant service costs, which negatively impact the economicviability of a well.

Another known system for lifting well fluids is a plunger lift system.The plunger lift system requires bottom hole pressure assistance toraise a piston, which lifts liquids to the surface. Like the pump jacksystem, the plunger lift system includes numerous supporting equipmentelements that must be maintained and replaced regularly to operateeffectively, adding significant costs to the production of hydrocarbonsfrom the well and eventually becoming ineffective due to lower reservoirpressures than are required to lift the piston to the surface toevacuate the built up liquids.

Thus, there is a need for a safer, longer lived, and more cost effectivepump system that effectively removes liquids from well bores that do nothave sufficient bottom hole pressure to lift the liquids to the surface.

SUMMARY OF THE INVENTION

It has now been found that that above-referenced needs can be met by adownhole pump system that powered by gas, preferably the gases producedfrom the subject well or wells. Specifically, the pump system includes apump housing having an engine end and a pump end. Disposed within theengine end of the pump housing is an “engine” having impeller orturbine-type blades fixably connected to a shaft disposed within saidhousing. Upon supplying pressurized gas to the engine-end blades beingthe shaft rotates. A “pump” is disposed within the pump end of thehousing, the pump comprising blades (preferably impeller-type) fixablyconnected to the same shaft. Upon the rotation of the shaft the pump-endblades lift the well fluids from the well.

In a preferred embodiment of the invention, the gas that drives the pumpis provided through a tubing string attached adjacent the engine end ofthe pump housing and that tubing string is disposed within a largerdiameter production tubing string. In this configuration well fluids areproduced through the annulus formed between the production tubing stringand the smaller diameter tubing string holding the pump.

In another preferred embodiment of the invention, the pump housing hasan outer diameter of at least 3.25 inches.

In yet another embodiment of the invention, a method of producing fluidsfrom a well is provided whereby a gas (preferably the gas from thesubject well or wells) is supplied to a pump disposed in a well, thepump including (1) an engine portion that is powered by said pressurizedgas and effectuates a rotation of a vertical shaft disposed within saidpump and (2) a pump portion that lifts fluids from said well by bladesdisposed within said pump portion affixed to said rotating shaft. In apreferred embodiment of this method a compressor is used to control thepressure of the gas and a separator disposed upstream from thecompressor to separate liquids from the gas.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and forfurther advantages thereof, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 is cross section view of the down-hole pump of the pump system ina preferred embodiment of the invention.

FIG. 2 is a schematic view of the down-hole pump and system of apreferred embodiment of the invention.

FIG. 3 is schematic view of the down-hole pump and system of analternative embodiment of the invention.

FIG. 4 is a schematic view of the down-hole pump of another alternativeembodiment of the invention.

FIG. 5 is a schematic view of the down-hole pump of another alternativeembodiment of the invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The present invention is a novel pump and pump system for use in theremoval of liquids from wells, especially, but not limited to, wellsthat have insufficient bottom hole pressure to lift the well liquids outof the well bore and to the surface. Referring to FIGS. 1 and 2, a firstpreferred embodiment of the present invention shall be described. FIG. 1and FIG. 2 illustrate a section of a typical hydrocarbon wellcompletion, which includes a casing string 100 with perforations 102adjacent the hydrocarbon- producing formation and a production tubingstring 104 with perforations 106. The production tubing 104 is installedwith a down hole standing valve or check valve 120 in the cased hole orwell bore. Preferably, the check valve/standing valve 120 is threadedonto the bottom of the production tubing 104, just above a perforatedtubing sub 122. This configuration allows for the pump 10 and 1″ tubing110 to be removed without exposing the formation to any produced fluidsand/or material that are captured inside of the annulus 108 between theproduction tubing 104 and the 1″ tubing 110. In the event that a needwas presented requiring the release of this fluid, the bottom of thestanding valve (ball and seat) 120 could be knocked off and a“Slickline” tool could be used to remove the standing valve.Additionally, the operator would have the option of removing the liquidsout of the tubing by means of forced air or any other type of pressurethrough the annulus that would make the tubing void of any fluids ormaterial prior to removing the standing valve 120.

The pump of the present invention, generally 10, is disposed within theproduction tubing string 104 at a depth adjacent perforations 102 incasing 100. Production tubing string 104 and casing 100 are conduitswhose use, construction and implementation are well known in the oil andgas production field. Pump 10 includes an engine end 12 and a pump end14, both encased in barrel 16. The pump, as shown in the embodiment ofFIGS. 1 and 2, is designed to fit within the well's production tubingand its size is determined by a number of factors, down holetemperatures, such as production tubing size, casing size and the amountof liquids and/or particulates (e.g., sand and coal fines) to beremoved.

In a preferred embodiment on the invention shown in FIG. 1 and FIG. 2,pump 10 is attached at the end of a 1-inch diameter (outer diameter)tubing string 110. Preferably, the pump is threaded onto the bottom ofthe 1-inch tubing and inserted into the production tubing 104, settingthe pump into a standard API seating nipple 130 and hanging the top ofthe 1-inch diameter tubing 110 in a set of tubing slips that are part ofthe wellhead on the surface. As shown, tubing string 110 and pump 10 aredisposed within the production tubing string 104, which is disposedwithin casing 100. For the purposes of this invention, pump 10 need notbe disposed entirely within production tubing string and may extendbelow the lower end of the production tubing string in the embodimentshown.

Although shown as one inch tubing, the tubing string 110 that supportspump 10 is not limited to one inch tubing and is preferably sized tomeet the particular needs of the well. For example, tubing string 110may comprise larger diameter tubing if large amounts of liquid areproduced and must be lifted from the well. In sizing the tubing string110, there are several factors to be taken into consideration, includingthe required feeding pressure/gas volume required to operate the engineend of the pump, the tensile strength of the tubing that the operatordesires in the wellbore, the size of the production tubing, the size ofthe well casing, and the amount of fluids that are calculated to beremoved from the wellbore.

Alternatively, instead of attachment to the end of a 1-inch tubingstring disposed within a production tubing string, pump 10 can beattached (threaded attachment) to the end of the production tubingstring 104 or the tubing string nearest the face rock (see FIG. 3). Inthis alternative embodiment, a seal assembly would be disposed at thetop of pump 10 into which a tubing string or pipe can be inserted tosupply appropriate gas pressure to the engine end of the pump.

Referring to FIG. 1 and FIG. 2, the pump 10 and pump system shall bedescribed. The components of pump 10 are encased in a cylindrical steelhousing (pump barrel) 16 much like conventional, well-known rod pumps.The pump and its components can be constructed of any suitable material,such as stainless steel, which will enable it to be utilized in harsh orcorrosive conditions. External seating cups 132 are disposed on the pumpbarrel, to isolate the engine end gas from the produced hydrocarbons,when utilized in the smaller diameter tubing. The seating cups 132 restupon a seating nipple 130 installed in the production tubing 104.

As stated previously, the pump includes an engine end 12 and a pump end14 disposed within the housing 16 (FIG. 1). The engine end and the pumpend may be separated by a permanent packed bearing, maintenance freeneedle or metal to metal type bearing 40 (preferably high temperature)and are operably connected by a common rod or shaft 42 that extends intothe engine and pump ends of the pump 10. Additionally, both ends of thepump preferably include stabilizer permanent packed or maintenance freebearings 44 and 46 (preferably high temperature) with ports 45 and 47for fluid and/or gas entry. This arrangement allows the pump to operatein a vertical or any angle, including all the way to a horizontalposition without a loss of efficiency or unnecessary pump wear. Attachedto the shaft 42 in the engine end 12 of the pump are blades 50 that arepitched to move fluids (especially gas) away from the ported bearing 44in the engine end. Although blades 50 are shown as impeller blades, in apreferred embodiment blades 50 are not impeller-type blades, but insteadis a turbine type blade design such as that disclosed in U.S. Pat. No.4,931,026 (see reference numeral 14), which is hereby incorporated byreference.

Still referring to FIGS. 1 and 2, exhaust ports 60 are provided in theengine end of the pump above bearing 40 to allow the driving gas toexhaust from the engine end of the pump. These exhaust ports areprovided with a ball check valve 62 that opens under pressure from thedriving fluids and closes to prevent fluid from entering the engine endthrough the exhaust ports when the pump is idle (See FIG. 3, referencenumerals 60, 62, 64 and 66 for ball check valve configuration). Attachedto the shaft in the pump end 14 of the pump are blades 52 (axialimpeller blades) that are pitched to move fluids upward toward exhaustports 64 in the pump end 14. Exhaust ports 64 are provided with a ballcheck valve 66 that opens when fluids are being lifted by the movingblades 52 in the pump end and closes to prevent fluid from entering thepump end through the exhaust ports 64 when the pump is idle. As shown(FIGS. 1-3), the axial turbine/turbines in the engine end are driven bypressurized (gas) to create the correct amount of torque and/orrevolutions per minute (RPM) of the shaft to create substantiallyreduced pressures at the pump inlet ports via the axial impellers in thepump end.

In a preferred embodiment of the invention, pump 10 would be driven bythe natural gas produced from the well. Generally, natural gas from theproducing formation and/or formations will flow up the production tubingor the annulus 109 between the production tubing and the casing 100 to aseparator 200 at the surface, which then feeds a surface compressor 210.Preferably, the surface compressor/compressors 210 would be designed tohave sufficient engine horsepower (HP), engine and gas water cooling,and compressor design, to exceed the highest pressure required to movethe static column of fluid that will exist if the pump were to becomeidle. Additionally, the compressor preferably would be versatile enoughto adapt to a wide range of inlet and discharge pressures without rodloading the compressor or having the engine die due to not enough HP.This versatility would allow the operator to adjust the dischargepressure or gas volume that feeds the pump engine. This would furtherallow the operator to adjust the surface pressure feeding the compressor210 from the surface separator 200, thereby allowing the operator toachieve optimum well bore protection and gas/oil flow.

In the arrangement shown (see FIG. 2), the pressure relieved off of theproducing formation can be controlled utilizing the inlet control valve202 on the surface separator which may prevent damage to producingsands/shale's. At the discharge line of the compressor 210 a pipe “tee”212 would be installed with a line 214 being laid back to the well boreto connect to the 1″ diameter (or larger) tubing (the “drive line”) towhich the pump 10 is connected and a second line 216 extends from thetee joint to a sales line. At this stage, any chemicals required toproduce the well such as paraffin, methanol for hydrates prevention, andcorrosion can be injected into the 1″ tubing 110, and swept down to theengine end 12 of the pump 10. A standard type of continuous injectionchemical pump (e.g., natural gas or electric), and either a threaded orwelded ½″ collar installed on the pipe for the injection point aresuitable for this purpose. This will allow the chemicals to have contactwith produced fluids to perform their functions while providing maximumprotection for the producing horizon/horizons from coming in contactwith these chemicals.

Continuing with the description of the preferred process/method ofoperation, a portion of the pressurized gas from the compressor 210 isdischarged through the tee joint 212 into the 1 inch drive line 110,with the remainder of the pressurized gas being discharged into thesales line 216 to continue on to sales. The amount of gas needed to bedirected to drive the pump 10 is adjustable by operation of anadjustable valve 218. For example, the adjustment of the amount of gascan be achieved utilizing a manual choke that can be locked at differentsettings or with a motor valve that can be operated either with apneumatic pressure controller alone or utilizing remote communicationstechnology. The amount of gas needed to operate the pump 10 will bedependent upon the pitch of the blades, length of the “axial turbine” inthe pump barrel, and the pressure required to lift the annular fluids,as well as other factors.

As illustrated in FIGS. 1 and 2 (gas path indicated by arrows), thedrive gas discharged into the tubing string 110 enters the pump throughthe ported bearing 44 at the engine end 12. The pressurized gas enteringthe engine end then acts upon the blades 50 causing the blades and shaft42 to rotate. Then, the pressured driving gas (fluid) is exhausted fromthe engine through the exhaust ports 60 located just above the isolationbearing 40 and into the annulus 108 between the one-inch tubing stringand the production tubing. With the common shaft rotating, the blades 52in the pump end 14 rotate as well, causing a vacuum (or suction) effectwhich draws fluid from the well through the ported bearing 46 at thepump end. The well fluids drawn into the pump end 14 are then forcedtoward and through the exhaust ports 64 located just below the isolationbearing 40 and into the annular space 108 between the 1-inch tubing 110and the production tubing 104. The well fluids then combine with thedriving fluids in this annular space and flow toward the surface and tothe separator 200. The mixture of the produced liquids and the naturalgas utilized for power, will create a lighter gravity fluid in theannular space 108 between the production tubing and the 1-inch tubingallowing for less force (pressure) to be required to lift both to thesurface for separation. FIG. 2 illustrates the flow of gas (arrowsindicating flow) in a preferred embodiment of the pump system.

As is evident from the description above, the preferred process isrepetitive, thus keeping the well bore clear of produced liquids andsand while allowing less back pressure on the face rock. By producing upthe casing annulus without the back pressure or friction lossesgenerally created by free liquids, the face rock or producing horizonwill yield additional amounts of gas and/or oil. This will extend thelife of the well, thus enabling the operator to recover potentialincremental reserves that may be otherwise uneconomic to produceutilizing existing conventional artificial lift methods.

Further, although the ball check valves used at the exhaust ports inboth the engine and pump ends of the pump have the primary purpose ofpreventing/reducing back flow of fluids into the pump, they also providea secondary benefit of allowing pressure testing of the productiontubing from the surface to check for any mechanical failures. This maybe done utilizing a pump truck that fills the annulus between the 1-inchand the production tubing with a neutral fluid, usually produced or saltwater, and then pressures up to a calculated pressure. Significantpressure leak-off may indicate that a mechanical failure of the 1-inchtubing has occurred. This can be determined by an increase in pressurein the 1-inch tubing as the annulus pressure depletes. The ball checksprevent the test fluids (and any debris or other foreign material) fromentering the pump. Should the 1 inch tubing not show a mechanicalfailure then the operator can evaluate if a rig is required to remove orunseat the pump and again apply pressure to the production tubing to seeif leak off occurs. This would determine if the mechanical failure is inthe production tubing. The check valve 120 installed at the bottom ofthe production tubing 104 would allow for this test procedure.

Additional benefits can be derived from the system described herein. Forexample, the system described above provides a means to increase liquidremoval from produced gasses. Simultaneously acting with the processabove will be an effective method of liquid removal from the compressordischarge gas prior to sales or custody transfer of the gas. This willoccur due to the reduction of gas pressure utilized for driving the pumpengine to the existing sales line pressure. The hot gas from thedischarge of the compressor that is not utilized for operation of thepump will cool when it is controlled or experiences a pressure dropcaused by the separator inlet controller. This will cause some of theentrained water and/or oil condensate to separate out of the sales gasstream and be recovered, utilizing the surface equipment on location.Thus, in the preferred embodiment of the invention, the primary(three-phase) separator 200 would remove all free liquids that areinitially removed from the wellbore prior to feeding the pressure to theinlet of the compressor 210. Then all produced liquids and any excessgas that is not utilized in the process of operating the pump and willbe controlled or choked back down to the sales-line pressure utilizingan inlet control valve 222 installed on a second (two-phase) separator230 that removes produced liquids and liquids that have fallen out ofthe gas stream due to pressure drop, allowing less saturated “cleaner”gas to continue on to the sale line 216 at line pressure andtemperature.

Referring to FIG. 3, there is shown an alternative embodiment of thepump and pump system of the present invention. The same referencenumerals used above and shown in FIGS. 1 and 2 are used in FIG. 3 forlike components and processes. FIG. 3 depicts an alternativeconfiguration where the pump 10 is attached directly to the productionstring 104 rather than a one-inch tubing string. As shown, in thisalternative embodiment, the pump is not set in a seating nipple.Further, in this embodiment, it is preferred that production tubing 104is held in place with a packer 300. In this embodiment, the process andsystem functions are the same as those described above; however, thepump 10 lifts fluids through the annulus 109 between the productiontubing 104 and casing 100. These fluids are lifted and then processed atthe surface as described in connection with FIGS. 1 and 2.

In another alternative embodiment of the pump system, a centralcompressor with a distribution piping system (holding a set pressure)can be used. This alternative configuration would give the same effectas having a wellhead compressor and is akin to a gas lift system wherethe power natural gas would be delivered to the well from one centralsite to cover several wells (e.g., 100-200 wells). In this alternativeembodiment, the gas flow would be the same as that shown in FIG. 2 anddescribed above in connection with FIGS. 1 and 2, with the exceptionthat only one surface separator would be needed.

Reference is made to FIG. 4 for another alternative embodiment of thepresent invention. The same reference numerals used above and shown inFIGS. 1-3 are used in FIG. 4 for like components and processes.Accordingly, the above descriptions made in conjunction with FIGS. 1-3apply with respect to the alternative embodiment depicted in FIG. 4 andwill not be repeated. Like FIGS. 1 and 2, FIG. 4 depicts a configurationdesigned to produce well fluids between the annulus 108 formed betweentubing string 110 and the larger diameter production tubing string 104.FIG. 4 illustrates a section of a hydrocarbon well completion, whichincludes a casing string 100 with perforations 102 adjacent thehydrocarbon-producing formation and a production tubing string 104 withperforations 106. The production tubing is installed in the cased holeor well bore. In the embodiment of FIG. 4, check valve/standing valve120 is a removable standing valve or vertical check valve that isinstalled into the seating nipple or “O-Ring” assembly 130 of the tubingstring 104. The seating nipple 130 is located at the bottom of theproduction string or one (1) joint of pipe up from the bottom such thatit is disposed below. This configuration allows for the pump 10 and 1″tubing 110 to be removed without exposing the formation to any producedfluids and/or material that are captured inside of the annulus 108between the production tubing 104 and the 1″ tubing 110. In the eventthat a need was presented requiring the release of this fluid, thestanding valve 120 would be removed utilizing a “Slickline” tool.Additionally, the operator would have the option of removing the liquidsout of the tubing by means of forced air or any other type of pressureforced down the annulus that would make the tubing void of any fluids ormaterial prior to removing the standing valve 120.

Still referring to FIG. 4, turbine blades or turbine means 50 areschematically depicted in the engine portion of the pump 10. For a moredetailed description and depiction of suitable pump engine turbine meansreference is made to U.S. Pat. No. 4,931,026 (see generally referencenumeral 14), which has been incorporated by reference. Because of thehigh rotational speed created by the turbine configuration (e.g.20,000-30,000 rpm), it is preferred that a vertical stabilizer bearing140 be used as shown.

Reference is made to FIG. 5 for another alternative embodiment of thepresent invention. The same reference numerals used above and shown inFIGS. 1-4 are used in FIG. 5 for like components and processes.Accordingly, the above descriptions made in conjunction with FIGS. 1-4(including the design of pump 10) apply with respect to the alternativeembodiment depicted in FIG. 5 and will not be repeated. As shown in FIG.5, a larger diameter pump 10 is threaded onto a larger tubing string 110(e.g., 2⅜ inch OD tubing) than that depicted in FIGS. 1 and 4 (1 inchtubing). In this alternative configuration, the pump 10 is located abovethe perforations 102 formed in larger diameter casing 100, such as aliner top. In a preferred aspect of this embodiment of the invention,pump 10 is housed within a housing or barrel 16 having an outer diameterof at least 3.25 inches. As shown in FIG. 5, pump 10 is disposed withina section of 3.25 inch (OD) tubing which is threaded to a 2⅜ inch tubingsection 110 above the pump 10. As shown, pump 10 is fixed within a 4½inch production tubing section 104 by a seating nipple or a seating cup132 which holds the pump in place and isolates the engine end 12 fromthe pump end 14 of the pump. The 3.25 inch tubing section 104 isthreaded below pump 10 to 2⅜ inch tubing (tail pipe) 114. In a preferredaspect of this embodiment of the invention, a packer is set below thepump instead of a down hole standing valve. Further, as shown in FIG. 5,preferably a string of “tail pipe” 114 or several joints of tubingextend below the pump 10, with the tail pipe set or landed at theoptimum place in the perforations. In a most preferred configuration,the tail pipe is smaller in diameter (e.g. 1½ inch) than the tubingstring 110 feeding the engine of pump (e.g., 2⅜ inch). This preferredconfiguration would increase velocity of fluids entering the tail pipeand would produce increased torque pressures for setting and releasingthe packer. Further, this configuration will allow more gas volume andless friction loss to the engine end, and increase velocities in thesmaller diameter tubing installed inside the larger casing.

The various embodiments of this invention have been described herein toenable one skilled in the art to practice and use the invention. Its isunderstood that one skilled in the art will have the knowledge andexperience to select suitable components and materials to implement theinvention. For example, those skilled in the art will understand thatcomponents such as bearings, seals and valves referenced herein will beselected to effectively withstand and operate in the harsh pressure andtemperature environments encountered in an oilk or gas well.

Although the present invention has been described with respect topreferred embodiments, various changes, substitutions and modificationsof this invention may be suggested to one skilled in the art, and it isintended that the present invention encompass such changes,substitutions and modifications.

1. A downhole well pump system comprising: a pump housing having anengine end and a pump end; an engine disposed within said engine end ofsaid housing, said engine comprising at least one engine-end bladefixably connected to a shaft, said shaft being vertically disposedwithin said housing and said at least one engine-end blade beingdesigned to cause said shaft to rotate when a pressurized gas flowsacross said at least one engine-end blade; a pump disposed within saidpump end of said housing, said pump comprising at least one pump-endblade fixably connected to said shaft, said at least one pump-end bladebeing designed to lift well fluids vertically upon rotation of saidshaft; and a string of tubing disposed within a wellbore and attached tosaid housing for providing a conduit through which said pressurized gasis supplied to said engine, said tubing string having an outer diameterand an inner diameter, wherein said pump housing has an outer diametergreater that the inner diameter of said tubing string.
 2. The downholewell pump system of claim 1 wherein said at least one engine-end bladecomprises a plurality of blades.
 3. The downhole well pump system ofclaim 2 wherein said plurality of blades comprises impeller-type blades.4. The downhole well pump system of claim 2 wherein said plurality ofblades comprises turbine-type blades.
 5. The downhole well pump systemof claim 1 wherein said at least one pump-end blade comprises aplurality of blades.
 6. The downhole well pump system of claim 5 whereinsaid plurality of blades comprises impeller-type blades.
 7. The downholewell pump system of claim 1, further comprising a check valve at anoutlet of said pump.
 8. The downhole well pump system of claim 7 whereinsaid pump housing having an outer diameter of at least 3.25 inches. 9.The downhole well pump system of claim 1, further comprising a checkvalve at an outlet of said engine.
 10. A method of producing fluids froma well comprising: collecting fluids produced from said well; separatingliquid from gas in said fluid; compressing said gas to control thepressure thereof; and supplying said compressed gas to a pump disposedin said well, said pump including (1) an engine portion that is poweredby said pressurized gas and effectuates a rotation of a vertical shaftdisposed within said pump and (2) a pump portion that lifts fluids fromsaid well by blades disposed within said pump portion affixed to saidrotating shaft.
 11. A method of producing fluids from a well comprising:receiving pressurized gas, the pressurized gas including gas producedfrom the well, the well including a well casing surrounding a tubingstring and an annulus between the casing and the tubing string, theannulus being open from a pay zone to a point upwell of a pump disposedin the well and the annulus being in fluid communication with a pointadjacent a wellbore opening at the surface; and supplying thepressurized gas to the pump disposed in the well, the pump adapted foremploying the pressurized gas for generating a force for lifting thefluids from the well, wherein the pressurized gas is supplied to thepump prior to the pressurized gas entering a sales line.
 12. A method inaccordance with claim 11 wherein said pump is disposed at a pay zonewithin the wellbore of said well.
 13. A method in accordance with claim11, wherein said pump includes an engine portion and a pump portion,said method further comprising: driving said engine portion with saidgas; and lifting said fluids from said well using said pump portion. 14.A method in accordance with claim 13, wherein said pump portion isattached to a production tubing string in said well.
 15. A method inaccordance with claim 11, wherein said pump includes an engine portionand a pump portion, said method further comprising: driving said engineportion with said pressurized gas to effectuate movement of a shaftdisposed within said pump; and driving said pump portion with saidmovement of said shaft to lift said fluids from said well.
 16. A methodin accordance with claim 15, wherein said movement of said shaft is in arotational direction.
 17. A method in accordance with claim 15, whereinsaid step of driving said pump portion includes driving a blade disposedwithin said pump portion with said movement of said shaft to lift saidfluids from said well.
 18. A method in accordance with claim 15, whereinsaid step of driving said pump portion includes driving at least oneimpeller blade disposed within said pump portion with said movement ofsaid shaft to lift said fluids from said well.
 19. A method inaccordance with claim 15, wherein said step of driving said engineportion includes flowing said gas across a blade disposed within saidengine portion to effectuate movement of said shaft.
 20. A method inaccordance with claim 15, wherein said step of driving said engineportion includes flowing said gas across at least one impeller bladedisposed within said engine portion to effectuate movement of saidshaft.
 21. A method in accordance with claim 15, wherein said step ofdriving said engine portion includes flowing said gas across at leastone turbine blade disposed within said engine portion to effectuatemovement of said shaft.
 22. A method in accordance with claim 11,wherein said fluid comprises liquid and gas, said method furthercomprising separating said liquid from said gas.
 23. A method ofproducing fluids from a well comprising: compressing at least a portionof gas produced from said well with a compressor to produce pressurizedgas; receiving said pressurized gas, said pressurized gas including gasproduced from said well; and supplying said pressurized gas to a pumpdisposed in said well, said pump adapted for employing said pressurizedgas for generating a force for lifting said fluids from said well.
 24. Amethod in accordance with claim 23, wherein said compressor is awellhead compressor.
 25. A method in accordance with claim 23, whereinsaid compressor is a central compressor, said method further comprisingdistributing said pressurized gas via a distribution piping system. 26.A downhole well pump system comprising: a pump configured to employpressurized gas for generating a force for lifting fluids from a well,the pressurized gas including gas produced from the well, the wellincluding a well casing surrounding a tubing string and an annulusbetween the casing and the tubing string, the annulus being open from apay zone to a point unwell of a pump disposed in the well and theannulus being in fluid communication with a point adjacent the wellboreopening at the surface, wherein at least a portion of the pressurizedgas is supplied to the pump via the tubing string prior to thepressurized gas entering a sales line.
 27. A downhole well pump systemin accordance with claim 26 wherein said pump is disposed at the payzone within a wellbore of said well.
 28. A downhole well pump system inaccordance with claim 26 wherein said pump includes a check valve on anoutlet thereof.
 29. A downhole well pump system in accordance with claim26, wherein said pump comprises an engine portion and a pump portion,said pump portion attached to a production tubing string in said well.30. A downhole well pump system in accordance with claim 26, whereinsaid pump comprises: a shaft disposed within said pump; an engineportion adapted to employ said gas to effectuate movement of said shaft;and a pump portion, adapted to employ said movement of said shaft tolift said fluids from said well.
 31. A downhole well pump system inaccordance with claim 30, wherein said movement of said shaft is in arotational direction.
 32. A downhole well pump system in accordance withclaim 30 wherein said pump further comprises a blade disposed withinsaid pump portion, said blade adapted for lifting said fluids from saidwell based on said movement of said shaft.
 33. A downhole well pumpsystem in accordance with claim 30 wherein said pump further comprisesat least one impeller blade disposed within said pump portion, said atleast one impeller blade adapted for lifting said fluids from said wellbased on said movement of said shaft.
 34. A downhole well pump system inaccordance with claim 30 wherein said pump further comprises a bladedisposed within said engine portion, said blade effectuating saidmovement of said shaft based on a flow of said gas across said blade.35. A downhole well pump system in accordance with claim 30 wherein saidpump further comprises at least one impeller blade disposed within saidengine portion, said at least one impeller blade effectuating saidmovement of said shaft based on a flow of said gas across said blade.36. A downhole well pump system in accordance with claim 30 wherein saidpump further comprises at least one turbine blade disposed within saidengine portion, said at least one turbine blade effectuating saidmovement of said shaft based on a flow of said gas across said blade.37. A downhole well pump system comprising: a pump adapted to employpressurized gas for generating a force for lifting fluids from a well,said pressurized gas including gas produced from said well; and acompressor for compressing at least a portion of gas produced from saidwell to produce said pressurized gas.
 38. A downhole well pump system inaccordance with claim 37, wherein said compressor is a wellheadcompressor disposed proximate said well.
 39. A downhole well pump systemin accordance with claim 37, wherein said compressor is a centralcompressor adapted for providing said pressurized gas to said pump via adistribution piping system.
 40. A method of producing fluids from awell, the fluids including production gas, said method comprising:creating, using pressurized gas, a reduced pressure inlet for liftingfluids from the well, the pressurized gas comprising gas produced fromthe well, the well including a well casing surrounding a tubing stringand an annulus between the casing and the tubing string, the annulusbeing open from a pay zone to a point upwell of a pump disposed in thewell and the annulus being in fluid communication with a point adjacenta wellbore opening at the surface; and supplying the pressurized gas viathe tubing string to the pump for creating the reduced pressure inletprior to the pressurized gas entering a sales line.
 41. A method inaccordance with claim 40 wherein said pump is disposed at a pay zonewithin a wellbore of said well.
 42. A method in accordance with claim40, further comprising: pressurizing a portion of said production gaswith a wellhead compressor to produce said pressurized gas.
 43. A methodin accordance with claim 40, further comprising: pressurizing a portionof said production gas with a central compressor to produce saidpressurized gas; and supplying said pressurized gas to said well via adistribution piping system.
 44. A method in accordance with claim 40,wherein said fluids comprises liquid and gas, said method furthercomprising separating said liquid from said gas.
 45. A downhole wellpump system for pumping fluids from a well, comprising: a pump mechanismconfigured to employing pressurized gas to create a reduced pressureinlet for lifting fluids from a well, wherein the pressurized gascomprises gas produced from the well, wherein the pressurized gas issupplied to the pump mechanism via a tubing string prior to thepressurized gas entering a sales line, the well including a well casingsurrounding the tubing string and an annulus between the casing and thetubing string, the annulus being open from a pay zone to a point unwellof the pump mechanism disposed in the well and the annulus being influid communication with a point adjacent the wellbore opening at thesurface.
 46. A method in accordance with claim 45 wherein said pumpmechanism is disposed at a pay zone within a wellbore of said well. 47.A downhole well pump system in accordance with claim 45, wherein saidpump mechanism further comprises at least one check valve at an outletthereof.
 48. A downhole well pump system in accordance with claim 45further comprising a pump housing, said pump mechanism being disposedwithin said pump housing.
 49. A downhole well pump system in accordancewith claim 45 wherein said pump mechanism is attached to a productiontubing string in said well.
 50. A downhole well pump system inaccordance with claim 45, wherein said fluid comprises liquid and gas,said pump system further comprising a separator for separating saidliquid from said gas.
 51. A downhole well pump system for pumping fluidsfrom a well comprising: a compressor for controlling a pressure of apressurized gas; and a pump mechanism adapted for employing saidpressurized gas to create a reduced pressure inlet for lifting fluidsfrom a well, wherein said pressurized gas comprises gas produced fromsaid well, said well including (a) a well casing surrounding a firsttubing string and (b) an annulus between said casing and said firsttubing string, said annulus being open from said pay zone to a pointupwell of a pump disposed in said well and said annulus being in fluidcommunication with a point adjacent the wellbore opening at the surface.52. A downhole well pump system in accordance with claim 51, whereinsaid compressor is a wellhead compressor.
 53. A downhole well pumpsystem in accordance with claim 51, wherein said compressor is a centralcompressor, said downhole well pump system further comprising adistribution piping system for carrying said pressurized gas to saidwell.
 54. A method of producing fluids from a well having a wellboreopening at the surface, a pay zone, a casing, the method comprising:disposing a first tubing string within the casing such that an annulusbetween the casing and the first tubing string is in fluid communicationbetween a point proximate the pay zone and a point proximate thewellbore opening; disposing a pump in the first tubing proximate the payzone, the pump configured to use a pressurized gas to generate a forcefor lifting the fluids to the wellbore opening; pressurizing a gas, thegas including gas produced from the well; and supplying the pressurizedgas to the pump.
 55. A method in accordance with claim 54, whereinpressurizing a gas including gas produced from the welt comprises:separating gases from the produced fluid; and compressing the separatedgases.
 56. A method in accordance with claim 54, wherein the gasproduced from the well includes gas separated from the produced fluidand gas from the annulus.
 57. A method in accordance with claim 54,wherein supplying the pressurized gas to the pump comprises supplying afirst portion of the pressurized gas to the pump and a second portion ofthe pressurized gas to a sales line.
 58. A method in accordance withclaim 57, further comprising controlling a pressure of the first portionof the pressurized gas to control operation of the pump.
 59. A system inaccordance with claim 57, further comprising a valve for controlling apressure of the first portion of the pressurized gas to controloperation of the pump.
 60. A system in accordance with claim 57 furthercomprising collection piping for collecting gas produced from aplurality of wells, wherein the compressor pressurizes the gas collectedgas.
 61. A system in accordance with claim 60 further comprisingdistribution piping coupled to the compressor for supplying thepressurized gas to pumps in a plurality of wells.
 62. A system forproducing fluids from a well having a wellbore opening at the surface, apay zone, and a casing, the system comprising: a first tubing stringdisposed within the casing such that an annuls between the casing andthe first tubing string being in fluid communication between a pointproximate the pay zone and a point proximate the wellbore opening: apump disposed in the first tubing proximate the pay zone, the pumpconfigured to use a pressurized gas to generate a force for lifting thefluids to the wellbore opening;and a compressor coupled to the well andto the pump, for pressurizing a gas including gas produced from the welland supplying the pressurized gas to the pump.
 63. A system inaccordance with claim 62, further comprising a separator for separatinggases from the produced fluid, wherein the gas produced from the wellincludes gases separated from the fluid.
 64. A system in accordance withclaim 63, wherein the gas produced from the well includes gas from theannulus.
 65. A system in accordance with claim 62, wherein supplying thepressurized gas to the pump comprises supplying a first portion of thepressurized gas to the pump and a second portion of the pressurized gasto a sales line.